Tubulars and methods for delivery of chemical in a well

ABSTRACT

An apparatus for wellbore treatment includes a tubular with one or more solid, erodible blocks on its outer surface. The blocks carry a chemical for wellbore treatment that is released in the wellbore by erosion of the blocks against the wellbore wall. A method for wellbore treatment employs the tubular to release the chemical in the well by erosion of the blocks.

FIELD OF THE INVENTION

The present invention relates generally to drilling and well servicing operations, particularly tubulars and methods for introducing chemical to a well bore,

BACKGROUND OF THE INVENTION

In the process of drilling a well into an oil and/or gas bearing formation, a drilling fluid or “mud” is pumped into the developing well bore through the drill pipe and exits through nozzles in the rotating drill bit mounted at the end of the drill pipe. Drilling fluids perform several functions essential to the drilling of oil or gas wells, one being the lubrication of the drilling string while the pipe is moving. While many different kinds of secondary lubricants are added to the mud, there are generally two types including mechanical or solid lubricants, and liquid lubricants.

Various types of drilling fluid are known including aqueous-, hydrocarbon-, or synthetic-based fluids, emulsions, fresh or brackish water, or fluid containing inhibitors or salts. Gases may also be used (for example, air drilling or use of nitrogen to lower the density or create a foam of a base fluid). During the drilling operation, a portion of the drilling fluid may filter or flow into the permeable or fractured subterranean formation surrounding the well bore and is therefore not returned to the surface for recirculation. This lost portion is generally referred to as “lost circulation” which has a significant economic impact on the operation. Lost circulation, particularly of hydrocarbon-based drilling fluids, may negatively impact the environment.

It is therefore desirable to have a system of tubulars in the drill pipe, pipe, tubing, coiled tubing, liner and casing to hold and place advanced materials, previously unusable materials, or reactive materials which are initially separated but mixed together when necessary, to control losses as or before they occur. This would save time and money with quick on demand activation and placement with minimized assembly tripping and set times to control drilling fluid losses.

Drilling out cement plugs left in the hole to control losses or stabilize the well bore can often have detrimental effects on the drilling fluid while re-drilling through hard or soft cement. There is also a risk of drilling off the top of the cement plug into a new hole and not following through to the previously drilled hole sections, thus causing other well bore or well planning issues. This is a common problem while drilling with water-based fluids.

Increased lubrication of the drill pipe, tubing, coiled tubing, liner, and casing is desirable to create more efficient drilling operations since it is an expensive problem currently facing the drilling industry. With the increase in horizontal drilling and multistage fracturing of production zones, the added expenses associated with these types of drilling and well completions means that the rate of penetration (ROP) and lateral length or total measured depth (TMD) of extended reach drilling can greatly affect the cost effectiveness of drilling operations. Torque and drag of the drill pipe, tubing, coiled tubing, casing, and liner runs can greatly limit the length of drilling, working over, or completing wells to extended TMD's. The lateral distance of running liners or casing, and the time and costs required to drill longer lateral lengths can be greatly increased as ROP can be limited by not allowing enough weight translation or push from the weight of the vertical drill pipe on the lateral drill pipe to reach the drill bit and provide force to the drill bit to apply cutting pressure to the rock face. It is therefore desirable to improve methods for reducing torque and drag occurring inside steel casing or in underground formations on the drilling assembly or drill pipe, tubing, coiled tubing, liners and casing to increase the ROP and extend the TMD's reachable in a given size of new hole for both drilling operations and running casing or liners.

SUMMARY OF THE INVENTION

Thus, in accordance with a broad aspect of the present invention, there is provided a tubular for use with a down hole assembly, the tubular comprising: a tubular wall, a block carried on the tubular wall, the block including a wellbore treatment chemical capable of being released by erosion of the block.

In a further embodiment of the present invention, there is provided a method of chemically treating a well having a wellbore wall, the method comprising: running into the well with a tubular having a tubular wall with an outer surface and a block on the outer surface, the block being a solid and including a chemical for wellbore treatment; and treating the well with the chemical by contacting the wellbore wall with the block to release the chemical in the well.

In accordance with the method, running of the tubular may include drilling a well, completion or work over of a well, with a string such as of drill pipe, tubing, coiled tubing, or other downhole assemblies comprising the tubular bearing the block.

It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.

BRIEF DESCRIPTION OF THE FIGURES

Referring to the drawings, several aspects of the present invention are illustrated by way of example, and not by way of limitation, in detail in the figures, wherein:

FIG. 1 is a schematic illustration of one embodiment of a tubular having blocks of chemical attached to its outer surface.

FIG. 2A is a schematic illustration of one embodiment of a tubular having spring-loaded pads including blocks of chemical recessed at an angle on its outer surface. FIG. 2B is a schematic illustration of a cross-sectional view through line I-I of the tubular of FIG. 2A.

FIG. 3 is a schematic illustration of one embodiment of a tubular having disc-shaped blocks of chemical inserted on its outer mid-surface and forming pads about the tubular.

FIG. 4 is a schematic illustration of one embodiment of a tubular machined to accommodate the attachment of blocks of chemical on its outer surface by set screws and plates.

FIGS. 5A and 5B are schematic illustrations of one embodiment of a tubular having blocks of chemical inserted on its outer mid-surface.

FIG. 6A is a schematic illustration of one embodiment pipe string with a pipe connected therein carrying a tubular of the “add-on” type, which is in the form of a fixed, non-rotating, hinged collar including pads formed of chemical blocks and positioned at a desired point on the outer surface of a pipe. FIG. 6B is a schematic perspective illustration of the tubular of FIG. 6A apart from the string.

FIG. 7 is a schematic illustration of one embodiment of a tubular of the “add-on” type which is non-rotating and is positioned on the outer surface of a pipe.

FIG. 8 is a schematic illustration of one embodiment of a tubular in the form of a fixed, non-rotating collar having most of its outer surface formed of a block of chemical material, and positioned at a desired point on the outer surface of a pipe.

FIG. 9A is a side elevation of a tubular wall useful to form a tubular. FIG. 9B is a section along line A-A of the tubular wall of FIG. 9A with blocks installed thereon. FIG. 9C is a section along line B-B of FIG. 9B.

FIG. 10 is a schematic illustration for an assembly for molding blocks.

DETAILED DESCRIPTION

The detailed description set forth below is intended as a description of the present invention and is not intended to represent the only embodiments contemplated by the inventor. The detailed description includes specific details for the purposes of providing a comprehensive understanding of the present invention. However, it will be apparent to those skilled in the art that the present invention may be practiced without these specific details.

The present invention relates generally to drilling and well servicing operations, particularly tubulars and methods for introducing chemical to a well bore. A tubular of the present invention may be assembled as part of the downhole assembly for drilling or service. The tubular is used to carry a block of chemical for delivery of the chemical directly to a wellbore in which the downhole assembly is employed, for underground formations or specific areas of desired application in a drilling operation or service operation. Upon rotation or reciprocation of downhole assembly, including for example, the pipe, drill string, tubing, coiled tubing, or down hole tool, including the tubular, the chemical is thereby released. The chemical may be eroded by fluid flow therepast or preferably by the mechanical and physical movement between the chemical block and another surface. The chemical block may be eroded such that it becomes released in the wellbore, for example, it may be abraded, scraped, smeared, applied, or bonded directly onto the well bore wall, which may be an exposed formation or a liner such as casing, to achieve the desired application. The chemical block is therefore softer than the wellbore wall, either the formation or a liner. The chemical block is solid, but softer than formation rock and softer than steel. The chemical forming or in the block may be released in the well such as, for example, lubrication, reduction in torque and drag conditions in the well bore, well bore formation inhibition, plugging or sealing of fractures or pores, or control of lost circulation zones.

Accordingly, in one embodiment, the tubular carries solid blocks of chemical (i.e., solid chemical or chemical in a solid carrier) for wellbore treatment. The blocks are carried into the well bore where they erode slowly to introduce the chemical to the well bore. The chemical is, thus, delivered down hole via the tubular and applied directly to the well bore wall as the downhole assembly is moved in or out, rotated or reciprocated, in the course of drilling, work over, or completion operations. Possible examples of a suitable chemical for well bore treatment include a plugging material, a lubricity additive, a stabilizer or a well bore formation inhibitor.

Drilling, work over, and completion fluids are commonly utilized to provide lubrication and inhibition to underground formations. Fluids carry lubricants, inhibitors, and/or loss circulation control products through or alongside the drill string, tubing, coiled tubing, casing, or liner strings to points in a well. Most fluids are aqueous- or hydrocarbon-based, or emulsions thereof in suitable phases or percentages. The fluid may be a drilling fluid, well kill fluid, or a frac fluid.

A well kill fluid is a drilling fluid with a density sufficient to produce a hydrostatic pressure to substantially shut off hydrocarbon or water production flow into a well from an underground formation, for example, regular drilling fluid weighted up with barite, hematite, other solids, or dissolvable salts to increase the fluid density.

Additional lubricants added to fluids can be either liquid-based which are a part or percentage of the fluid, or liquid lubricants with an affinity to attach themselves to metal surfaces or as a barrier. Mechanical or solid lubricants can be added to a fluid in an attempt to carry the solids (such as for example, walnuts, glass or polymer beads, graphite, molybdenum sulfide, or other solid materials) down hole to aid in lubrication of the downhole assembly (i.e. drill string, tubing, coiled tubing, liner or casing or downhole tool). Providing lubrication with solid materials is an attempt to pebble the well bore, smooth out or ride above the surface imperfections, insert solid into the filter cake of the bore hole wall, or provide a medium to which the pipe, tubing, liner or casing assembly can ride above the well bore rock wall or drilling fluid filter cake, on the solid materials. Certain solid lubricants such as for example, graphite or molybdenum sulfide, have laminar layers or structures that pull apart or slip apart easily, allowing movement or providing lubrication by permitting two surfaces to move as the layers pull apart.

Lubrication of the well bore can be complicated due to the surface disconformities of the rock face, the interactions of steel, and various types of underground formations of rock drilled, structure, layering, formation lithology, formation hardness or softness encountered. Lubricants are typically added in large volumes since the volume of the drilling fluid in the circulation system is generally treated in entirety and there is currently no precise method of lubricant delivery. Large volumes of lubricants must be used as they are carried by the entire or a large portion of the drilling fluids system. Current liquid lubricants include many different types of chemistries and base oils including, but not limited to, esters, hydrocarbons, vegetable oils, surfactants, salts, amines, and combinations thereof to reduce friction forces or contact forces.

Accordingly, in another embodiment, the tubular carries solid blocks of a lubricity additive (i.e., solid lubricity additive or lubricity additive in a solid carrier). This type of tubular is useful for installing in a string (i.e. a drill string or installation string) where lubricity is needed to place the string into the well. The blocks are carried into the well bore where they erode slowly to introduce the lubricity additive to the well bore where needed, namely where the string is riding against the well bore wall, to facilitate movement of the string over the wellbore wall. Cased hole and open well bore drill pipe torque and drag are thus reduced by delivering lubricity additive down hole via the tubular to apply the lubricity additive directly to the open hole or lined walls as the downhole assembly is moved in or out, rotated or reciprocated, in the course of normal drilling, work over, or completion operations. The amount of lubricity additive needed for the operation is, thus, reduced as it is applied only to the area where direct lubrication is required. The tubular allows the usage of expensive lubricants not currently available to the drilling or service industry such as, for example, solid or semi-solid self-lubricating chemicals, semi-solid lubricants, grease materials, synthetic solid lubricants, new chemicals, and other lubricant types. Such additive chemicals are generally too expensive to use when treating entire fluids systems that may contain large volumes. Further, damage to the underground formations, the drilling fluid, drilling equipment, environment including the carbon footprint left transporting materials, and rig operations is minimized by decreasing drilling times and more selectively applying lubricants rather than treating the entire drilling fluid system with the lubricant. The horsepower required to drill, complete, or work over wells with pipe or tubing assemblies at both well service and drilling operations may be eased.

Any common base drilling fluid, workover, or completion fluid may be used in accordance with the present invention.

During drilling, a constant flow of whole mud into a formation is common. The formations to which whole mud can be lost include, but are not limited to, cavernous and open-fissured formations, very coarse and permeable shallow formations such as loose gravel, natural or intrinsic fractured formations, and mechanically fractured and easily fractured formations. Severe losses often result in the delay of the drilling operation and costly overruns of time and can induce more severe occurrences such as an influx of down hole hydrocarbons, well kick, blowout or loss of control of the well and down hole formations resulting in potentially severe consequences. Severe losses of drilling fluids often force drilling operations to stop, and down hole tubulars and equipment must be pulled out of the hole and laid down so that more aggressive measures can be taken to seal off the hole and control losses. Cement is often used in an attempt to control total losses. To introduce cement, the drill string must be pulled out of the hole and reworked so that problematic areas, such as restrictions, are reduced. The string must then be run back in the hole to the depth of losses or as close as possible. Cement is slurried on surface and pumped down the hollow drill pipe into the open hole. If the cement is set in the correct spot and properly hardens in the down hole environment, some losses may be controlled. This operation is often performed several times in attempt to control losses or to stabilize an underground formation as it is often common to experience losses of the drilling fluid once the cement is drilled out and the well bore continues to develop ahead.

Cementing operations are costly and time-consuming due to the cement setting, drilling out the cement in the hole, and repeated tripping of the drill string and drill string assembly to drill the well bore. Cement placed in the well bore can also be diluted or chemically affected by the drilling fluid; placed or set in the wrong portion of the hole and/or migrate due to cement's high density into another part of the well, potentially away from or below the intended zone or placement depth.

Accordingly, in another embodiment, the tubular carries blocks of a wellbore inhibitor (i.e., solid inhibitor or inhibitor in a solid carrier). This type of tubular is useful for applying the inhibitor directly to the formation wall such that the inhibitor is applied without requiring conveyance downhole in the base fluid. The inhibitor may comprise two chemicals (i.e., part A and part B chemistries) such as solid or semi-solid epoxies that can be eroded onto a bore hole wall at a specific point to apply and combine the materials to form hard set epoxy materials over lost circulation zones such as unconsolidated, fissured or fractured zones to control fluid losses or improve well bore stability.

The block of chemical can be a solid form of the chemical or an amount of the chemical in a solid carrier. The block may be formed in various ways, for example, forming a portion of the surface of the tubular, for example coating all or a part of the tubular or may form pads on the tubular. In the form of pads, the blocks are positioned and/or protrude to preferentially contact the wellbore wall as the tubular resides in the wellbore.

Formulations for use with the invention include, but are not limited to, chemicals that react with each other upon mixing. Chemicals that may be carried on the tubular include, for example, cement chemicals and epoxy resin components. At least two chemical components of the required formulation may be run in using one or more tubulars for exposure and blending upon demand. Where a plurality of chemical components is required for a particular formulation, these chemical components may be delivered via multiple tubulars, each containing different but separated components. Hence, multiple tubulars may be used, with each tubular holding chemical components to provide larger material placements if required; for example, multiple single tubulars may hold single material chemicals, with each being exposed and eroded together in the same area of the well bore. Upon activation, one or more tubulars may expose and erode their payloads of chemical. The string can then be pulled up and additional tubulars placed into the material previously eroded onto the well bore or steel wall where a second, or more, set of tubulars may be activated to expose the second, or more, parts of the chemical solution, upon command, to erode, mix and react with the first materials eroded into the well bore.

The tubulars can be of any diameter which is less than the diameter of the developing well bore or hole size in which they are to be run. In one embodiment, the diameter of the tubular ranges from about 1 inch to about 12 inches. The tubulars may be of any length required to carry out the desired application. In one embodiment, the length of the tubular ranges from about 0.1 meter to about 15 meters. In one embodiment, the tubular may be jointed into a string of pipe, liner or tubing, with the length of the tubular ranging from about 3 meters to about 9 meters. In another embodiment, the tubular may be of the add-on type, to be attached and secured to the outside of a string of pipe, liner, casing, tubing, or coiled tubing, with the length of the tubular ranging from about 0.1 meter to about 9 meters. In one embodiment, the tubular has a diameter ranging from about 1 inch to about 15 inches, and a length ranging from about 0.1 meter to about 15 meters. Preferably, the tubular has a diameter ranging from about 3.5 inches to about 12 inches, and a length ranging from about 1 meter to about 9 meters.

The tubular may be threaded at one or both ends. In one embodiment, the tubular has both male and female threads configured to engage corresponding threads of drilling pipe of the required drilling rigs, coiled tubing, or service rigs. The tubular can be milled to fit all industry standard or known thread types and connections and can be jointed into the coiled pipe or pipe system with thread connectors and thread crossovers for various thread types.

The tubular can be either of heavy weight construction or constructed within the normal parameters of the drilling assembly drill pipe for the service requirements of the operation. Construction to conform the pipe to normal drilling assembly parameters, materials, metals or specifications, tubular selection, construction materials, and position in the drill string, tubing, coiled tubing, liner, or casing will be apparent to one skilled in the art.

As noted, in one embodiment, the tubular may be of an “add-on” type, rather than a self contained tubular ready for connection to a string. An add-on (also called parasitic, saddlebag, etc.) tubular may for, example, a cylinder that is sleeved over a base tubular or may be a clamp (sometimes called a wrap around), for example in the form of a cylindrical member with axial sections hinged together or fully separable with locks to secure the axial sections of the cylindrical member onto the existing drill pipe, tubing, coiled tubing, liner, or casing as an attachment. This type of tubular is non-rotating and secured, for example fixed, placed, mounted, or otherwise, to the outer surface of the drill pipe, tubing, coiled tubing, liner, or casing. The tubular thus allows for the site specific attachment of solid blocks of chemical of chemical onto pipe, tubing, casing, or liner assemblies without having to join the tubular into the assemblies. Such a tubular allows chemical blocks to be attached to a continuous string of tubing or pipe (for example, a coiled tubing rig) which cannot be broken apart at any point to allow insertion of a tubular. The add-on tubular can be applied anywhere on a continuous pipe or tubing string and secured thereon as a non-rotating or fixed tubular that contains and holds the pads. In one embodiment, the add-on or wraparound tubular can be applied over joints of pipe or other areas which are typically in contact with the well bore. In one embodiment, the add-on tubular is in the form of a hinged collar which can be opened, closed, locked, and set with a suitable fastener such as a set screw to be secured to the outer surface of the drill pipe, tubing, coiled tubing, liner, or casing. In one embodiment, the tubular is in the form of a fixed, non-rotating collar may have the block of chemical forming pads thereon or may have most of its outer surface comprising the block of chemical material, rather than pads.

As used herein, the term “payload” refers to the amount of the chemical that is carried by the tubular. In one embodiment, the payload is fixed on the tubular so that it is always exposed and protrudes from the outer surface of the tubular for immediate, constant application of the chemical through movement or erosion during rotation, reciprocation, tripping, and movement in or out of the well, or drilling, with pipe, tubing, coiled tubing or pipe.

In one embodiment, the chemical payload may be housed or recessed within the tubular, and deployed or extended outwards by mechanical actions, applied pump pressures, or springs. The pads may be recessed into an internal bay within the tubular for a specific application or to protect them from erosion in a certain part of the well. Activation of the tubular can be electronic or mechanical to deploy or extend the chemical payload. In one embodiment, activation is triggered by preset fluid pressure increases on the tubular to ratchet or push out the blocks while the fluid is circulating. The blocks, for protection thereof, can be recessed, or otherwise stored back inside the bay of the tubular, and may be exposed to the well bore by action of the pumping pressure exerted on the tubular or inside the tubulars from the circulation of the drilling fluids around, down, and back up the hole or well bore. In another embodiment, springs recessed behind the blocks may either apply pressure to the block to ensure its full extension at all times, or apply additional pressure on the pad to the application wall and to replenish the protruding amount of the block when it becomes worn down.

In one embodiment, the payload of the tubular may be attached and formed onto detachable, interchangeable, replaceable blocks secured on the outer surface of the tubular. The replaceable blocks may be secured on the tubular in payload bays or attachment points using various fastening means and methods including for example, set screws, screws, snaps, bolts, tongue and grooves, or secured by glues or epoxies, and/or welded into place.

In one embodiment, the blocks may be attached to the tubular at any angle including axially aligned or off-axis. If desired, the angle may be selected so as not to interfere or go against the drilling assemblies' right hand drive orientation when rotating. The angle of the block can be slightly curved, offset, or both to wrap around part of the tubular, such that as the pipe is rotated, the block allows, promotes or induces a flow in the direction with the drilling fluid flow and not back against the fluid flow.

The tubular thus serves to carry blocks of chemical in place during movement of the pipe, tubing, coiled tubing, liner, or casing, and may allow the blocks to be replenished during use or easily interchanged or replaced either when desired or when the tubular is at surface.

In one embodiment, the tubulars, and therefore the blocks carried thereon, may be moved rotationally or axially up and down in the well to apply the chemical. Where the block of chemical includes a lubricant, movement of the tubular, and blocks thereon, provides lubrication by applying mechanically eroded lubrication materials into the well bore, thereby providing an ideal surface for the reduction of torque and drag on the drill pipe while drilling the well bore, or for running tubing, coiled tubing, liner, or casings. The erosion rate and timing of chemical release can be controlled for example, by provision of additional tubulars and blocks at specific points, selection of block materials, and chemicals to have controlled rates of erosion on selected surfaces. As the blocks are rotated and erode their chemical materials, they also provide a surface to rest a portion of the weight of the drill pipe, thereby moving or breaking friction easily or at a lower rate of friction to the steel wall or open hole formation than the normal metal of the drill pipe.

The blocks may be of any shape or size that is conducive to installation on a pipe outer surface, rotation of the pipe and flow of the drilling fluid, and provides a sufficient erosion period and enough material to apply chemical to the bore hole or steel wall. The blocks can be orientated and placed in any position or configuration. The blocks are abraded by the wellbore wall upon contact with it, thus reducing the amount of chemical other materials at fixed or controlled rates for applying the chemical or other materials directly to the wall, for example in a layer embedded in the rock face, irregularities of the rock surface, or onto steel surfaces.

The blocks may mount directly on the outer surface of the tubular, as by use of adhesives, direct molding, mounting structures such as retainers or fasteners, etc. Alternately or in addition, the blocks can be secured onto a mounting structure for installation on the tubular outer surface. The mounting structures may include one or more of a plate, a retainer, a pin, a screen, a receptacle, etc. The blocks may be secured to the mounting structures as by encapsulation, adhesion or fasteners or the block may be formed to incorporate the mounting structure, as by molding the solid material of the block about the mounting structure.

The block may be solid so that it can be carried into the well and the chemical therein released in the well by erosion, as by smearing, abrasion, etc. As noted, the chemical may be solid or the carrier for the chemical may be solid. By solid, it is meant that the block is not a liquid and is, thus, capable of being carried into the well on a tubular. Thus, for example, a solid block may include a hard or soft solid material, a semi-solid material, a compressible material, a solid which has open cavities therein, for example cells containing gas or liquids, or a solid with multiple components for example a laminate, etc. The solid is capable of being eroded by wellbore conditions. Thus, the solid is softer than formation rock and softer than steel, as will be the usual surfaces against which the blocks will contact for erosion when downhole. The solid for example, will have a hardness less than steel (i.e. less than 3 Mohs scale) and in one embodiment, the solid may have the hardness of wax or soft polymer such as may have a needle penetration (ASTM D1321) of 0.1 to 20 10⁻¹ mm or a Shore A Durometer of 10 to 100.

The blocks may be formed or the composition selected to control, for example limit, the rate of erosion. For example the block composition can include chemicals that have no affinity for themselves and do not build layer upon layer, but rather leave a layer of chemical into or onto the irregularities of the steel or rock face until such time as they are filled or smoothed, after which no further block material is eroded away on that surface. The block composition may be selected, as by selection of the chemical composition, including the carriers, chemicals or fillers, to slip across an already deposited layer without depositing more material, such that additional chemical is applied only after the previous layer of the chemical is removed, as by use, dislodgement or consumption, by the rotation or reciprocation of the tubular, or by reaction, or infiltration to the rock formations or steel surfaces.

As noted, the blocks may contain lubricants, inhibitors, or stabilizers, fluid loss materials, two or more part epoxies alone or in a mixed composition with other materials.

The chemical may, for example be solid, semi-solid or liquids, or combinations thereof which are used alone to form the block, if they are solid or semi-solid, or which are suspended and/or blended into a composition including a base component, such as a carrier or a reinforcement, for formation of the block.

The base component may assist with formation of the block, may resist or control the erosion rate of the materials, may provide impact or shock resistance, etc. and can include resin, epoxy resin, polymer, fluoropolymers, polytetrafluoroethylene (PTFE), polyethylene, high density polyethylene (HDPE), low density polyethylene (LDPE), wax, polyethylene wax, paraffin wax, microcrystalline wax, or a combination thereof in various percentages. The base components for the block may also include reinforcements to provide additional erosion rate control, with additions of reinforcement materials such as, for example, (i) fibers, for example fiberglass, cellulose, Kevlar™, metal such as steel or other metal wools, synthetics, composite, cloths or other fibers or (ii) foams, such as for example, open cell foams of natural or synthetic materials, including polymers, cellulose, metal, or other foams.

Since the block composition is to be applied directly to a steel casing, steel liner, or open hole well bore through erosion, the composition is also sufficiently resistant to mechanical and fluid erosion to allow its application thinly over long distances of the well or at controlled rates. Multiple tubulars and block types may be run in separated by spacing intervals or in series close to an enlarging or developing well bore or in both areas, and/or any desirable section of the pipe, tubing, coiled tubing, liner or casing assemblies. The chemical preferably meets certain requirements (for example, hardness, needle penetration, melt point, transition point, chemical resistance, hydrocarbon or water resistance, heat transfer and adhesion to pad surfaces, the well bore wall, formation types, and/or irregularities) in order to withstand environmental or down hole conditions.

For desired properties and applications, the composition including the wellbore treatment chemical may be mixed in either dry powder or solid form, or mixtures thereof, and may be heated, partially melted, or fully melted to yield a blend, emulsion, or suspension that once molded, formed, or cooled into the desired shape and thickness, creates the block. Prior to cooling or molding, liquid emulsions or suspensions of chemical may be controlled or improved to ensure stability or to increase the thickness and suspension of the mixtures or chemical by holding equal distribution of the combined materials with liquid emulsifiers, suspension increasing solids (for example, treated or amine treated bentonites), yield point or rheology modifiers, and viscosifiers (solid or liquid).

Chemical lubricants may be formed from either liquid lubricants converted to the solid state by mixing and forming with solidifiers, or solid lubricants held in suspension within a solidifier. Lubricants can be formed of mixtures of any ratio (expressed as percentage) of liquid and solid lubricants. Liquid lubricants may include, but are not limited to, esters, hydrocarbons, grease type formulations, or combinations thereof. Solid lubricants may include, but are not limited to, graphite, molybdenum bisulfide, solid bearing type materials used for pebbling or beading of a surface, glass beads, polymer beads, waxes, PTFE, HDPE, LDPE, or combinations thereof impregnated or mixed into a composition for a block.

The chemical can be made with mixtures of materials brought to a molten state or suspended in molten materials that are used to carry and contain the solid or liquid lubricants which are cooled (at specific rates to control the quality and performance of the chemicals) to solid or semi-solids in shaping molds and molded to mounting structures such as metal pads or base plates, supports, etc. forms which are to be inserted or mounted onto the tubular surface or bay such as a cavity opening on the outer surface, and secured in place by screws, latches, straps, snaps, adhesives, engagement, or other suitable fastening means.

Plastics and waxes or mixtures thereof, or mixtures of different types and ratios of other materials are raised in temperature above the melting points of the various combined materials. Other solid lubricants or liquid lubricants are then blended into the molten fluid to form a suspension or emulsion. Suspension increasing or modifying materials (for example, treated clays) may be added to the molten fluid to create higher yield point suspensions in order to suspend solid particles blended into the molten mixtures, or present during the metal pad adhesion and cooling process of the chemicals onto the pad base structures or tubular attachment plate points.

Emulsifiers and wetting agents may also be added to the molten mixtures to create stronger fluid emulsions, thereby further suspending liquids, immiscible liquids, and/or solid particles, and holding the molten mixtures together in a blended or homogenous state during the metal pad adhesion and cooling process of the chemicals onto the pad base structure, or structures. Injection molding or compression molding, high temperature sintering, low pressure molding, or other techniques can be used to create block structures. Applied cooling of the block molds can be utilized to create specific pad features and functions based on the applied temperature and rate of cooling.

Block chemicals and construction with materials such as, for example, PTFE or other high temperature materials, may require specialized formation processes such as high temperature sintering to ensure that they are formed and cooled into the desirable solid block structure, shape, and to minimize imperfections such as blend inconsistency or air spaces.

The block may have a balanced or planned mixture of chemicals for exposure while the block is reduced in size due to controlled erosion. A block may have a plurality of layers of different materials that are exposed as the blocks are eroded on the well bore or steel surface at a specific time or later in the well section, or based on time or length of exposure. As such, layers may be exposed and erode one at a time with a specific material or a blend of materials being released for a particular time period. During erosion, further specific materials are exposed for later specific time periods. This process can continue through many materials throughout the block. Blocks may also have an outer shell that is sacrificial to ensure the desired materials of the block are delivered only a certain point in a deep well or well bore before the desired material is exposed or eroded onto the well bore. The blocks may also have a sacrificial material that is hard or harder than the desired wellbore treatment material so that the tubular can be sent into the well bore and placed into the desired section without any loss of the desired pad chemical or material. This sacrificial outer coating can be removed by focused movement of the blocks on their tubular allowing the outer layer to be removed by rapid metal surface contact. The sacrificial outer coating can also be formed of a material designed to dissolve or melt upon reaching a certain temperature or friction pressure. The mechanical and chemical properties of the pad chemicals may vary due to the desired service application, application rate, durability, and/or chemical components.

The tubulars may hold one or more blocks of various purposes, shapes, sizes, constructions, wellbore treatment chemicals and/or compositions.

The tubulars can be easily selected or changed when designing or handling the string. In some embodiments, the blocks can also be selected or changed out by provision of an installation that allows removal and replacement of the blocks. In one embodiment, a block can be changed by removing the block retainers and removing and replacing the in place blocks with new blocks. As such, the tubular may be re-utilized. On surface or once back at surface, the tubulars can be serviced to have new, different, additional, and/or blends of blocks put into place, and secured onto the tubulars as required to continue to apply new or different material chemicals (for example, lubricants or other materials) in a manner that does not require significant additional time or tubular servicing. The block replacement procedures are fast and easy such that the service crew can easily select, replace, and secure new blocks onto the tubular in order to meet the requirements of the application at that given time and to do so without interference or delay to other operations of the rig or overall operation utilizing the tubulars.

Multiple tubulars may be run in series with each other, joined in sections to any given distance, or positioned in various areas of the drill string, jointed pipe series. Those skilled in the art will appreciate that the number or positioning of the tubulars or tubular sets in the drill pipe series or drill string, or in any given string of pipe, tubing, coiled tubing, liner, or casing string may be varied to allow for multiple applications, sustained application, or re-application; for example, multiple attempts or applications may be needed to seal off the well bore, or reduction of torque and drag may be required in multiple specific areas of the drill string.

The tubulars can be made from any metal used in the construction of the drill string or string of pipe with which the tubular is to be utilized. Tubulars may be constructed from non-magnetic metals or alloys to avoid interfering magnetically with other systems in the drill string or pipe string. The tubulars may also be shaped to prevent differential sticking or to reduce the surface area of the tubular exposed to the open hole formation on or with the filter cake formed on the bore hole wall from the drilling fluid. Appropriate placement of the blocks is also made to prevent differential sticking of the tubular in the open hole formation. The shape, size, direction, and orientation of the pads do not obstruct or interfere with the circulation of fluids, drilling fluids, or kill fluids by permitting good flow through of moving fluids and solids around and past the tubulars so as not to interfere in the hole cleaning of the well bore and to prevent differential sticking due to surface area contact forces applied from the filter cake onto the tubular surface area.

The tubulars may also assist in the cleaning of material, drill solids, and cuttings created by the developing well bore from the bottom of the well bore through the agitation of those solids as materials are applied or eroded to the well bore. The shape of the blocks can be such that they assist in the mechanical removal of solids and/or cutting beds from the bottom of the well bore or hole through mechanical agitation or disruption of the settling of the solids into critical areas or length of the well bore as the tubulars and pads are rotated or moved.

Examples of tubulars to be connected into a string are shown in FIGS. 1, 2A, 2B, 3, 4, 5A and 5B.

For example, FIG. 1 shows a tubular 10 having a tubular wall 12 with ends (only one is shown 12 a) threaded for connection into a string, herein a pipe string for example of drill pipe, liner, casing, etc. The tubular wall may have various inner and outer diameter dimensions depending on the purpose of the tubular, its necessary strength and the dimensions of the wellbore in which it is to be employed, as will be appreciated. The tubular wall defines an inner wall surface 12 b and an outer surface 12 c. Blocks 16 a, 16 b of chemical are attached to outer surface 12 c to be accessible in the annulus between the wellbore wall and tubular 10. The blocks can take various forms, as illustrated. For example, each block 16 a is generally rectangular and formed of a solid chemical material and is attached with its long dimension extending substantially parallel with the long axis x of the tubular. Blocks 16 a are each attached to the tubular outer wall by a quick insert. Blocks 16 b are each circular in plan view. Blocks 16 a and 16 b each are spaced apart about the circumference of the tubular wall such that flow channels 18 are defined between the blocks, radially outwardly of outer surface 12 c.

FIGS. 2A and 2B illustrated another tubular 10 according to the invention. Tubular 10 also includes a tubular wall 12 with threaded ends 12 a′, 12 a″. The tubular wall defines an inner wall surface 12 b and an outer surface 12 c. Blocks 16 c of chemical are attached to the tubular wall to be exposed on outer surface 12 c. In this embodiment, blocks 16 c are each installed in a cavity 20 recessed into the tubular wall. When tubular 10 is ready for use, blocks 16 c are installed in cavities 20 such that at least a portion extends beyond the outer diameter of tubular wall 12, but a backside portion 16 c′ of each block resides within its cavity. The blocks may be biased out as by fluid pressure or by springs to form pads that are biased radially out to bear against the wellbore wall W, as the tubular resides in the well. This maintains contact between the pad and the wellbore wall and ensures that an amount the payload of chemical remains available for contact with the wellbore wall by continuing to push the recessed portion adjacent backside 16 c′ of the block outwardly.

Fluid pressure may be communicated from the tubular's inner bore through a port to a chamber behind the block to thereby bias it out when pressure within the bore is sufficient. This arrangement may require seals and retainers for the blocks to preserve fluid pressure in the bore and to prevent the block from being expelled completely.

Alternately or addition, a biasing member, such as a spring 22, is installed between the backside portion of the block and the cavity. As such, blocks 16 c form spring-loaded pads for the tubular.

A ratcheting mechanism may be employed with the biasing means in order to control inward movement of the block after it has been biased out. The ratcheting mechanism may permit only outward movement or may permit radially outward and inward movement.

Blocks 16 c each are spaced apart about the circumference of the tubular wall such that flow channels 18 are defined between the blocks. As best appreciated by the sectional depiction of FIG. 2B, in use a tubular forms an annular space between wellbore wall W and tubular outer surface 12 c. In many operations, fluid is intended to be moved through the annular space. Blocks 16 c may extend out from outer surface 12 c to be more readily available to contact wellbore wall W. In fact, in this embodiment blocks 16 c are biased to preferentially act as pads that contact the wellbore wall. While blocks 16 c form occlusions in the annular space, flow channels 18 are spaces between the blocks through which the fluid may flow.

In the illustrated embodiment, blocks 16 c are each elongate and include an angled portion that, if extended, would form a helical form about the long axis x of the tubular. As such, flow channels 18 are likewise angled and redirect any fluid passing therethrough to control annular flow characteristics. Herein, the angle is about 15° to 20° off axis x, but other angles may be employed, as desired.

FIG. 3 illustrates another tubular 10 according to the invention. In this embodiment, tubular wall 12 includes ends 12 a′, 12 a″ that have outer diameters enlarged relative to some smaller diameter outer surface portions 12 c′ intermediate the ends. This is similar to some drill pipe tubulars. However, tubular wall 12 further includes at least one larger diameter outer wall portion 12 c″ between ends 12 a′, 12 a″. A plurality of blocks 16 d of chemical are positioned on the larger diameter outer wall portion 12 c″. In this way, the blocks are positioned where they are readily accessible for bearing against the wellbore wall. The blocks form pads about the tubular.

FIG. 4 is a schematic illustration of another embodiment of a tubular 10, this one having a tubular wall machined with cavities 20 on its outer surface to accommodate the attachment of blocks 16 f of chemical for wellbore treatment. One or more blocks 16 f are positioned in each cavity 20 and are retained therein by retainers including plates 38 secured over a portion of the cavity and the block therein by set screws 40.

FIGS. 5A and 5B are schematic illustrations of one embodiment of a tubular 10 having blocks 16 e of chemical inserted on its outer mid-surface. In this embodiment, tubular wall 12 is constructed of a mandrel with ends 12 a′, 12 a″ and an outer surface 12 c. A retainer ring 34 forms a central, raised shoulder on the mandrel, as by welding on the mandrel. Retainer ring 34 includes a plurality of blades 36 connected thereof that extend out axially from the retainer ring towards at least one end, but herein blades 36 extend from ring 34 towards each end. Blades 36 are spaced apart forming slots therebetween. A block 16 e of wellbore treatment chemical may be positioned in each slot. In particular, blocks 16 e may each be secured to a mounting structure such as a backer plate that slides under the blades while the block slides into the slot and is exposed between two blades. A plurality of rings are sleeved and secured over the mandrel. The rings secure the blocks into the slots. The rings may include for example, a top retainer ring nut 24, one or more retainer rings 26 and a bottom retainer ring nut 30. The ring nuts 24, 30 are positioned at ends of the set of rings and are secured at least by set screws 32. In this embodiment, and the rings are sleeved over the mandrel and secured on either side of blocks 16 e, holding the blocks in the slots of the retainer ring. The blocks are therefore replaceable by removing the ring nuts and retainer rings 26 and sliding the blocks out of the slots between blades 36.

The blocks protrude out radially beyond an outer diameter of blades 36. Blocks 16 e are spaced apart about the circumference of the tubular such that axially extending flow channels 18 are defined between the blocks and radially outwardly of blades 36.

Blocks 16 e form protruding pads through which the tubular can bear against the wellbore and the chemical forming the blocks can be eroded away to be released or placed in the wellbore.

Examples of add-on tubulars are shown in FIGS. 6A to 9.

For example, FIGS. 6A and 6B shows a tubular 110 a on a pipe string 150 a and apart from the string, respectively. The pipe string 150 a includes a pipe 152 connected therein carrying tubular 110 a, which is of the “add-on” type in the form of a fixed, non-rotating collar including pads 116 a of chemical blocks on its outer surface 112 c. The tubular includes a cylindrical wall 112 that has two axial sections 112 e, 112 f, each defining a semi cylinder, connected by a hinge 154 extending axially between the two axial sections. Opposite the hinge are latching edges 156 on each section including corresponding latches 158, which may be unlatched to open the tubular (as shown in FIG. 6B) and which may be brought together and latched to install tubular 110 on a string (as shown in FIG. 6A).

Tubular 110 may be positioned at a desired point on the outer surface of a pipe in a string 150 such that pads 116 a are exposed for application of the block chemical onto the wellbore wall.

FIG. 7 is a schematic illustration of another embodiment of a tubular 110 b of the “add-on” type which is non-rotating and is positioned on the outer surface of a pipe string 150 b. In this embodiment, the inner wall surface 112 b of tubular 110 a is formed to snugly fit about a pipe joint, which is the connection between two pipes 152 b in a drill string. Tubular 110 b cannot rotate or slide axially relative to pipe string 150 b so that it moves with the pipe string and blocks 116 b including chemical for wellbore treatment can be applied on the wellbore wall as the pipe string moves.

FIG. 8 is a schematic illustration of one embodiment of a tubular 110 c in the form of a fixed, non-rotating collar having most of its outer surface formed of blocks 116 c of chemical material. Tubular 110 c in this embodiment, includes a wall 112 c formed two axial sections 112 e, 112 f that are fully separable but are lockable at edges 156 c to form a cylindrical collar. Each section 112 e has its outer surface substantially covered by a block 116 c. Tubular 110 c may be positioned at a desired point on the outer surface of a pipe and may be run into a well to transfer the block material, which includes a chemical for wellbore treatment, onto the well wall.

FIGS. 9A to 9C show another tubular for delivery of wellbore treatment chemical to a well. The tubular 210 is shown assembled in FIGS. 9B and 9C, including tubular wall 212 and blocks 216 on an outer surface 212 c of the tubular wall. FIG. 9A shows only the tubular wall 212 of the tubular without blocks 216 installed.

Tubular wall 212 includes ends 212 a threaded for connection into a string. The tubular wall may have various inner and outer diameter dimensions depending on the purpose of the tubular, it's necessary strength and the dimensions of the wellbore in which it is to be employed, as will be appreciated. The tubular wall defines an inner wall surface 212 b and an outer surface 212 c.

Tubular wall 212 includes hardfacing 213 adjacent ends 212 a, in particular between each end and the closest cavity 220. The hardfacing, being more durable than the metal forming wall 212, protects the wall against wear. Thus, cavities 220 are protected from damage due to wear of the tubular should the blocks become worn down such that the tubular wall rides along the wellbore wall. This permits the tubular wall to be reused as by installing new blocks.

Blocks 216 of solid composition including a chemical for wellbore treatment are installed in cavities 220 formed on outer surface 212 c of the tubular wall. Blocks 216 are attached to outer surface 212 c to be accessible in the annulus A between the wellbore wall W and tubular 210.

Blocks 216 are each installed in a cavity by a mounting structure including pins 260 that pass through holes 262 in the block and holes 264 in tubular wall 212. The holes 262, 264 may be aligned when a block is placed in its cavity and the pins may be passed through and secured. In this embodiment, blocks 216 are also installed by adhesives. In particular, shock absorbing materials such as sprays, liquids, foams or preformed liners of polymers, adhesive, polyurethane, rubber, etc., are applied or installed between blocks 216 and their cavities to create a tighter fit, to provide a backside support and to reduce vibration of the block against the cavity in the tubular wall. Shock absorbing materials may be applied before installation of pins 260. Of course other mounting solutions can be employed such as adhesives, physical engagement such as by structures including overlying retainer plates and rings, fasteners, slots, etc.

When installed, blocks 216 protrude beyond the surrounding surfaces of tubular wall outer surface 212 c and, thereby, form pads through which the tubular may bear against wellbore wall W. In one embodiment, blocks 216 protrude beyond the effective outer diameter OD defined by outer surface 212 c.

Blocks 216 are spaced apart about the circumference and length of the tubular wall such that flow channels 218 are defined between the blocks, radially outwardly of outer surface 212 c. In this embodiment, the material of tubular wall 212 is actually milled away between blocks 216 to form indentations in the original cylindrical form of the tubular wall. These indentations enlarge channels 218 to ensure good fluid flow and less annular restriction.

While other arrangements are possible, as illustrated here each block 216 is elongate and attached with its long dimension extending substantially parallel with the long axis x of the tubular. The cavities are formed to avoid weakening the tubular wall and according to the selected pattern for the placement of the pads. In this embodiment, cavities 220 have been formed to avoid weakening the tubular wall and to permit a substantially continuous outer diameter such that the tubular doesn't chatter as it rotates on the blocks in the well. In particular, cavities 220 are offset from each other both axially and circumferentially. For example, the cavities are each out of axial alignment with adjacent cavities along the long axis of the wall. Also, the cavities are out of circumferential alignment such the upper ends of the cavities about any circumference are not aligned on an orthogonal section relative to long axis. For example, the cavities closest to upper end each are formed with their upper ends at a different distance from the end such that these upper ends each are positioned on a different orthogonal section.

For example, in the illustrated embodiment, within each set of three pads formed by blocks 216, the pads are offset 120 degrees to one another. There are a plurality (herein six) sets of three pads equally spaced along the axis x. Each of these sets of pads is rotationally oriented relative to the adjacent set of pads; the rotational amount herein being 20 degrees. When viewed as a whole, this creates the effect of the pads forming a helical spiral on the outer surface 212 c along the long axis of the tubular wall. Of course, the length of the tool body, the number of pads in each set, the number of sets of pads, and the rotational orientation can all be varied to create various patterns of the pads on the tool body. Of course, the critical function of the tool is not necessarily tied to the specific geometry and placement of the pads on the tool body.

While the blocks 216 are each formed of solid composition containing a wellbore treatment chemical, they can take various forms. For example, blocks 216 in this illustrated embodiment are molded of wax such as polyethylene wax and contain a chemical such as a lubricant. Blocks 216 may be reinforced for erosion control, shock and impact protection by adding reinforcements such as fibers or foam into composition for the block.

Synthetic open cell foam materials can be placed inside the mold forms prior to filling the molds with the molten polyethylene wax/lubricant or other molten mixed compounds. Inside the molds the foam adsorbs the molten compounds and upon cooling and forming of the molded blocks, the foam provides an additional internal structure that increases the ability of the blocks to withstand impact or external forces.

Most types of open cell foams are suitable for this purpose including those of natural or synthetic materials including, for example, polyethylene and polyurethane foams. The foams may be of any size inside the mold, they may accommodate from 1% to 100% of the internal volume of the mold to which the molten materials will be vacuum pumped into for adsorption into and around the foam. The open cells of the foam reinforcements can be of any size in diameter.

The foam may be of any size or shape inside the molded blocks and may include a variety of sizes or shapes. The foam may provided by one or more pieces placed into the mold.

Another reinforcement could be fibers of natural or synthetic materials with or without open cell foam. Again, this reinforcement may also be incorporated to the blocks to provide internal structure and impact resistance.

Loose fibers or fibers that have been woven or arranged into mesh, felt, fabrics, or other forms and that contain internal voids or spaces between the fiber mesh can be utilized.

Some of the synthetic fibers as described herein can be described as similar to those woven into a material such as those found in scouring pads or sometimes attached to open cell foams in the form of kitchen sponges.

The fibers may be in the form of steel or metal wools of any strand size or length (such as course, medium, and fine steel wool pads).

These fiber reinforcements may be additionally used in any shape or size inside the molded compounds to add strength or impact resistance to the molded compounds being attached to the tubular.

In such an embodiment, bubbles may weaken the blocks. Thus, to create blocks with minimal bubble imperfections, the molds are sealed and vacuum filled with molten compounds in a heated oven with the molds under vacuum conditions, then allowed to cool with or without vacuum pressure or negative pressures applied to the inside of the molds. For example, with reference to FIG. 10, a mold 170 may be employed for formation of the blocks. The mold may include an inner mold chamber 172 shaped to define the shape of the block to be formed. One or more injection lines 174 may extend to chamber 172 from a supply 176 of composition to be molded to form the blocks. One or more vacuum lines 177 extend from chamber 172 to a vacuum pump 178. The mold chamber may be heated, as by placement of the mold in an oven 180.

Blocks may be cooled under either negative or positive pressures to reduce the effects of contraction of the cooled molten materials.

Molten compounds can be flowed into the molds under negative or positive pressures with the temperatures of the compounds closely controlled to just slightly above the melting points of the polyethylene waxes to further control the contraction of the polyethylene waxes during the curing or cooling period of the polyethylene wax compounds or other wax compounds.

Contraction of the wax compounds during cooling and hardening may also be controlled by cooling temperatures and rate control.

Block molds may also be constructed such that the contraction of the cooling materials is compensated such that the resultant blocks are an acceptable size or the correct size for attachment to the tubular.

When forming the block, reinforcement 182 may be placed in chamber 172 and the compound injected into it. Alternately, the reinforcement may be incorporated in the compound in the supply 176 and injected together to the mold. Reinforcements 182, if any, may be foams or fibers or any combination thereof the materials.

Mold 170 can be formed such that the holes 262 used to secure the blocks to the tubular are molded internally. Alternately, the blocks can be produced and the securing holes 262 drilled into the formed blocks.

The present invention may be used in various applications. In one embodiment, there is provided a method of running a string into a well, for example, drilling a well with drill pipe and drilling assemblies, running in a liner such as casing or otherwise completing the well, or performing a workover. The string includes one or more tubulars carrying blocks of chemical for wellbore treatment. Such chemical may be, for example, lubricity additive, or other materials. The blocks contain the chemical in solid form or a solid carrier for the chemical and the blocks slowly erode at desired rates on contact with the wellbore wall, for example casing, liner, or the exposed borehole wall. The chemical is thus applied directly to the wall for a specific purpose as part of a drilling or well service operation with an assembly or drill string of tubulars, tubing, coiled tubing, and/or pipe.

In another embodiment, there is provided a method of drilling a well, completion or work over of a well, with drill pipe, tubing, coiled tubing and/or drilling assemblies including one or more tubulars housing or carrying interchangeable pads comprised of a wellbore treatment chemical, such as a lubricity additive or other materials which reduce the frictional forces of the pipe or tubing assembly on the string by riding on and slowly eroding chemical, lubricity additive, or other materials. Such chemicals or materials are applied directly to and erode against the wall such that they are applied, for example embedded, smeared, or are otherwise placed on the wall, such as into or onto the irregularities of the rock walls or metal surfaces.

In another embodiment, there is provided a method of stabilizing an underground formation from losses, hydrating or sloughing into the well bore using tubulars carrying blocks of chemical that alone or in combination with other chemicals down hole provide stabilization, such as by formation of stabilizing material such as cement. Highly effective solid two part resins are introduced into the well bore quickly and upon command. The tubulars are placed within a drill string, tubing string, coiled tubing or drilling assembly, and release chemicals such as reactive materials that, when mixed together, yield hard, generally inert materials, epoxy resins and two or more part hardening chemistries, cement chemicals or materials to control drilling fluid losses, inhibit, or stabilize the well bore and formations. The invention thus allows the initial separation of components which harden or react once combined to form set materials such as hard set cement until such time as they are required to be mixed to achieve a specific effect in a well.

The cements and/or resins are eroded into the well bore where they can mix together, set up, harden, and seal off cracks, pores, micro-fractures, spaces, and voids of all types and sizes either permanently, semi-permanently, and/or temporally seal off the well bore area exposed to the chemical formulations. The hardened reactive material can seal off the open hole and/or seep into the surrounding well bore area and infiltrate, permeate or move into the open or partially open cracks, pores, fractures or underground zone required to be sealed off. Then the cement, solid resin, one and two or more part reactive sealant can be drilled out with the bit on the drilling assembly if required, allowing the continued drilling or advancement of the underground well bore with reduced drilling fluid losses and minimal time lost to the drilling operations. The materials eroded onto the steel casing or bore hole wall (for example, chemical, cements, solid resins) can be sent down hole in separate chambers or sections of the tubular or drilling tool in advance of any losses or down hole stability problems. Upon potential fluid losses, seepage losses, total losses, drilling fluid losses or down hole formation instability, the tubulars may be activated either electronically or mechanically from surface to expand the payload.

As the payload of chemical is released or exposed, the drill or tubing string can be pulled up while rotating to mix the chemicals. As the blocks erode against the wall, the assembly can be pulled part way back out of the hole, over and above the first release point as the payload components are allowed to mix and become active or chemically react to form the desired sealant, plug or material in the bore hole or developing borehole. After a set or desired time interval to allow the chemical reactions to occur and for the materials to set up, harden, or form, the assembly and bit can then be run back in the hole and set on top of the new plug (hardened reactants or materials) where they can be drilled out. Drilling ahead may continue and/or additional tubular(s) may be activated to release additional mixture or chemical mixtures as necessary. Once the reactants are mixed and placed on the bore hole wall (as the drill pipe is rotated in the well bore), the natural pressure developed by the drilling fluid column (hydrostatic pressure) will further force the chemicals, resins or portions thereof into rock face, micro fractures, surface deformities, and pores to seal, stabilize, lubricate, or inhibit shale hydration in the well bore as the material(s) harden.

The chemicals may be applied directly to the wellbore wall, thereby presenting a minimal volume of residual or over-mixed materials that previously would have hardened in the open well bore or required greater time and effort to drill out and remove the residual materials. The mixed chemicals may exhibit a faster set time, hardening time, and curing time compared to some cements; incorporate chemically adjustable set up times; provide well bore stability direct to the bore hole wall; seal off loss zones; and present few chemical problems or incompatibilities with most drilling fluids. This will further save money as the drilling fluid is not contaminated drilling out the cement, particularly cements with water based fluids.

The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are know or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or “step for”. 

We claim:
 1. A tubular for use with a down hole assembly, the tubular comprising: a tubular wall, a block carried on the tubular wall, the block including a wellbore treatment chemical capable of being released by erosion of the block.
 2. The tubular of claim 1, wherein the wellbore treatment chemical comprises a plugging material, lubricity additive, or well bore formation inhibitor.
 3. The tubular of claim 2, wherein the chemical comprises a lubricity additive.
 4. The tubular of claim 3, wherein the lubricity additive comprises graphite or molybdenum disulfide.
 5. The tubular of claim 2, wherein the chemical comprises a well bore formation inhibitor.
 6. The tubular of claim 5, wherein the inhibitor comprises epoxy.
 7. The tubular of claim 1, wherein the block is a solid including a carrier comprising polymer, polyethylene, fluoropolymers, PTFE, resin, epoxy resin, HDPE, LDPE, wax, polyethylene wax, paraffin wax, microcrystalline wax, or combination thereof.
 8. The tubular of claim 7, wherein the block further includes a reinforcement comprising foam or fibers.
 9. The tubular of claim 8, wherein the carrier is polyethylene wax, the reinforcement is an open cell foam and the chemical is a lubricity additive.
 10. The tubular of claim 1, wherein the block is secured in a recess on the outer surface of the tubular wall.
 11. The tubular of claim 1, wherein the block is detachably secured on the outer surface of the tubular wall.
 12. The tubular of claim 1, further comprising a mounting structure for securing the block to the tubular wall.
 13. The tubular of claim 1, further comprising a sacrificial outer coating over the block.
 14. The tubular of claim 1, further comprising a second block on the tubular and herein the second block includes a second chemical that is different than the chemical.
 15. The tubular of claim 1, wherein the tubular is configured for attachment about the outside of a wellbore string.
 16. The tubular of claim 1, having threads at one or both ends to engage corresponding threads in a drill pipe.
 17. The tubular of claim 1, further comprising a cavity extending into the tubular wall from an opening on an outer surface of the tubular wall, the block installed in and protruding from the cavity and a mounting structure engaging the block and securing the block to the tubular wall.
 18. The tubular of claim 17, further comprising a shock absorbing material between the block and the cavity.
 19. The tubular of claim 17 wherein the block comprises a carrier including wax and a reinforcement in the carrier including foam or fibers and the chemical is a lubricity additive blended into the carrier.
 20. A method of running a string into a well, wherein the string carries one or more tubulars of claim
 1. 21. A method of chemically treating a well having a wellbore wall, the method comprising: running into the well with a tubular having a tubular wall with an outer surface and a block on the outer surface, the block being a solid and including a chemical for wellbore treatment; and treating the well with the chemical by contacting the wellbore wall with the block to release the chemical in the well.
 22. The method of claim 22, wherein treating includes applying a lubricant to the wellbore wall.
 23. The method of claim 22, wherein treating stabilizing an underground formation from hydrating or sloughing.
 24. The method of claim 22, wherein treating includes applying a well bore formation inhibitor to the wellbore wall.
 25. The method of claim 22, wherein contacting the wellbore wall includes eroding the block against the wellbore wall to apply the chemical to the wellbore wall.
 26. The method of claim 22, wherein running into the well includes supporting the tubular on the block, forming an annular area between the outer surface and the wellbore wall. 